In hydrocarbon and bitumen material deposits, such as oil and natural gas deposits, a significant fraction of the hydrocarbon resource remains unrecoverable even after primary natural pressure depletion production, secondary water flood, or pressure maintenance operations and even after tertiary enhanced techniques. Existing recovery techniques access only a small portion of known heavy crude reserves, with the balance remaining trapped underground. This is particularly true for the heavier crudes and bitumens in the 10 to 20 degree API (American Petroleum Institute) category, where the viscosity of the deposits may range to several poise. The deposits may also have adverse wettability and/or capillary forces preventing efficient recovery efforts. For example, heavy crudes with the higher viscosities make it difficult to push them toward a production well with water-based fluids. The heavier crudes tend to be younger in age and contain appreciable acidic components as determined by the Total Acid Number (TAN) measured via titration with potassium hydroxide (KOH). Also, many of these crudes may be classified as “dead” crudes in that there is little, if any, gas associated with them to provide a natural energy to assist with the recovery efforts.
Chemically enhanced recovery methods that are often employed include alkaline flooding techniques (U.S. Pat. No. 2,288,857, Subkow, 7/42) to react with the acidic components of the crude oil to create surfactants in situ and thereby emulsify a portion of the crude oil resulting in lower viscosity and wettability alteration. Alkaline silicates (U.S. Pat. No. 2,920,041, Meadors, 1/60) have been extensively studied over the years and applied for these purposes. Alkalis may be combined with added surfactants and polymers (U.S. Pat. No. 6,022,834, Hsu et al, 2/00) to improve performance and extend applicability to lighter crudes.
Thermally enhanced recovery technologies have also been used to reduce viscosity so that a greater portion of the crude can be forced to a production well before coning or water breakthrough occurs. These techniques include primarily steam flooding (U.S. Pat. No. 5,626,193, Nzekwu et al, 6/97) as well as, and to a lesser extent, in situ combustion techniques (U.S. Pat. No. 3,566,967, Shelton et al, 3/71). These techniques provide sufficient heat to the reservoir to lower the viscosity of the crude so it can be more easily driven to a production well. Steam is generally limited to shallower reservoirs (less than 3,000 ft) where heat loss to the wellbore and surrounding rock is manageable. Steam may be applied either in a huff-and-puff mode (injecting and producing from the same well) or continuously to drive crude to a dedicated production well.
Horizontal drilling techniques allow contact with a larger cross section of the reservoir such that steam soak via huff-and-puff can be effective. A combination of steam and alkalis in horizontal wells has been proposed (U.S. Pat. No. 4,892,146, Shen, 1/90). In situ combustion is not limited by depth but burns a portion of the recoverable reserves via injection of oxygen to create both heat and carbon dioxide, which is miscible with crude to swell and reduce viscosity.
Miscible technologies primarily include injection of carbon dioxide gas (U.S. Pat. No. 2,875,830, James W. Martin, Mar. 3, 1959), (U.S. Pat. No. 4,589,486, Alfred Brown et al, May 20, 1986) to swell the oil and reduce viscosity, but may include other gases such as hydrogen. Hydrogen is regarded as a less effective swelling agent, since it is on average about 15 times less soluble in crude. However, if the reservoir temperature can be raised above 425° C. (800° F.), there is the possibility for some in situ cracking/hydrogenation reactions (U.S. Pat. No. 2,857,002, E. F. Pevere et al, 10/58) to occur, which will improve the flowability of the crude. This can be further enhanced by injection of suitable catalytic agents.
Hydrovisbreaking (U.S. Pat. No. 6,328,104, Dennis J. Graue, Dec. 11 2001) is the application of hydrogen gas under elevated pressure and temperature to a heavy crude oil or bitumen, which results in a viscosity reduction of the heavy oil or bitumen to a lighter American Petroleum Institute (API) gravity material with reduced viscosity. The hydrovisbreaking process uses combustion units installed in injection wells to burn industrial-grade hydrogen with industrial-grade oxygen. This allows the injection of high-quality steam and hot hydrogen into the hydrocarbon-bearing formation to create the conditions required to promote in situ hydrovisbreaking. This thermal cracking process, involving hydrogenation of the heavy oil or bitumen is usually carried out at the refinery to process the heavy crude or bitumen into products that can be sold. Herron (Experimental Verification of In Situ Upgrading of Heavy Oil, E. Hunter Herron, October 2003) and others have shown that the hydrogenation reaction can be carried out to a significant extent in situ by application of hydrogen and heat. Conditions required were temperatures of 345° C. (650° F.) or greater and hydrogen partial pressure up to 8.7 megapascal (MPa), or 1,275 psia (88 bar). At these conditions, it was observed that viscosity reduction could be up to 99% with gravity increases of 5 to 10 degrees within several days.
Recovery efforts are often subject to widely varying permeability throughout the production zone or to fissures that direct fluids away from intended production wells. This leads to premature breakthrough and can bypass significant amounts of otherwise recoverable oil. Methods to deal with these challenges include various blocking techniques for the very severe channels and profile modification for less severe cases. Blocking methods include injection of cross-linkable organic polymers or other gelling/grouting inorganic agents such as silicates to rapidly form impermeable barriers in the highest permeability channels. Profile modification can be accomplished more gradually over time by deposition and buildup of gelatinous material (U.S. Pat. No. 2,402,588, Andresen, 6/46) in the highest permeability flow channels, thereby diverting fluids to less permeable channels containing oil that had been previously bypassed. Aqueous slugs of silicates alternating with multivalent cation salts (U.S. Pat. No. 4,081,029, Holm, 3/78) build precipitates in the primary channels to divert fluids. Also, gelatinous silicate precipitates may help to stabilize unconsolidated sands, thereby preventing unwanted production of sand.
Despite the existence of these techniques, large heavy crude reserves remain largely untapped, and these recovery methods add significant cost per barrel of recovered oil. These current enhanced oil recovery techniques often produce large quantities of brine at the surface, which can contain toxic metals and pose a threat to water sources if not properly contained.